Can FERC be too mean to NERC? The Federal Energy Regulatory Commission, that is, with its recent audit of the North American Electric Reliability Corp. Some say FERC's audit was too harsh and too broad. Some even link it to President Barack Obama's "anti-carbon agenda." Whatever is true, the audit has highlighted a power struggle that may be inevitable. Just how much is FERC the boss of NERC?
]]> What is fair game for FERC to oversee, given that it has a statutory mandate to oversee the electric reliability organization, which is NERC?The mandate may be a good part of the problem. When Congress put FERC in that role in 2005, it wrote certain things into the law, but it didn't go on and on with precise instructions about exactly what things NERC could have discretion about.
For about 40 years, NERC had run reliability oversight itself. A voluntary industry organization, it set standards for operating the system and it relied on voluntary compliance. It worked pretty well. But the big 2003 Northeast blackout convinced Congress that a volunteer industry regime wasn't enough, especially as the grid grew more and more interconnected and complex. Putting FERC in charge of it became the answer, but the transition has not been simple.
One of the things NERC has done for years is periodic assessments of the system's reliability. Through and with its "regional entities" (could there not be some more felicitous term for them?), NERC examines power supply, transmission capabilities and upcoming challenges, and identifies areas of concern.
It has no power to do anything about them, like order new supply or transmission. Its role is to write standards for various industry operators to comply with; FERC now approves these (or sends them back for redoing).
Sometimes NERC goes beyond the periodic assessments, which are referenced in law, to do special assessments of issues; in 2010 it did one on the possible impact of upcoming EPA rules, which taken together have been labeled by some in industry as forcing a "train wreck" for the power system. The argument is that thousands of megawatts of plants will have to retire rather than comply with the expensive requirements, or at least they will have to shut for a while during equipment installation. Reliability will be threatened, NERC said, echoing what many utilities say.
Last fall, NERC published an update to its initial EPA-rule assessment. The organization identified the regs as the top risk to reliability over the next several years.
EPA, of course, disagrees, as do some others, who acknowledge a big challenge but say the industry is well able to cope with it.
Was FERC piqued enough about it to come down hard in the audit of NERC? An editorial in The Wall Street Journal Monday said it was. It likened NERC to a whistleblower being silenced by FERC Chairman Jon Wellinghoff ("an EPA wingman") for daring to do the special assessments.
Web commenters on The Journal's editorial found the charge another excellent opportunity for rants about Obama's "socialist agenda." And maybe Wellinghoff has been piqued about NERC's conclusions. The chairman favors renewable power, energy efficiency, electric vehicles, the smart grid, and other features of movement to a low-carbon picture.
But the FERC-NERC relationship has been tense anyway. It would be surprising if it were not. Congress set up a regime wherein NERC would have to adapt to having a boss. (The law didn't specify that the "electric reliability organization" necessarily had to be NERC, but ... who else, with its treasury of technical expertise and after its decades of doing the job?)
Some of the stress has been coming from disconnects between FERC and NERC on the reliability standards that NERC must write. There are countless standards, too technical for most human beings to decipher. For some of them, the commission has been banging on NERC for a few years. "Critical infrastructure protection" is one standards area where FERC has shown a lot of impatience with NERC. Sometimes FERC remands a standard to NERC for rewriting because it's not specific and tough enough for its liking.
Both FERC and NERC officials have said at various times over the last year or so that relations were getting better, even as a "natural tension" continued as almost inevitable. At the same time, Wellinghoff did say in an interview with Platts in December that he had "real, real, real serious issues" with NERC.
When it certified NERC in 2006, FERC said it would audit the organization; it audits the companies it regulates. Was this particular audit, begun in August, "highly unusual," as the Journal said? It may have gone beyond the usual to comment on things audits do not normally assess, but some would say that's because NERC is far from the usual sort of company FERC regulates. It's unique, in fact. The setup is new and novel. So what in fact is appropriate for FERC to examine?
Holiday parties, the cost of which the audit staff criticized?
The costs of running NERC come ultimately from electricity ratepayers. Utilities that distribute power to customers, and whose costs are paid by the customers, are highly scrutinized by their state regulators. What is reasonable to leave to discretion?
The audit staff identified areas of concern -- employee compensation, method for reporting and tracking employee time and expenses, handling of retirement plans, method of paying board members, and more. There can be disagreements about many of these things, and there is agreement on NERC's side that some of the things could use improvement.
But the two are now trading formal charges and countercharges about how the audit was done, who informed whom about what, and when, and what things are reasonable to expect.
Is there a smoking gun for the Journal's contention that NERC is being punished for the EPA-rule assessments? A whiff of smoke may attach to footnote 48 in the audit, which refers to the periodic assessments NERC does as having been approved activities, but then goes on to say NERC "has assumed even greater assessment responsibilities in other areas."
"The degree to which such assessment and monitoring activities currently ongoing should be deemed statutory is therefore also an element that audit staff believes should be revisited," the footnote says.
Argument will spool out over coming weeks, months, maybe years.
If the lights go out big-time again, lawmakers may see a need to define something more regimented, if not hand the entire structure formally and completely to FERC, which after all would be in the hot seat on Capitol Hill. Whether it would make sense, or make any difference in actual reliability, is impossible to know.
]]>"It's the West Coast, man," one trading source said. "When you want to explain to someone why gasoline changed so much, just say, 'It's the West Coast, man.'"
It's also the nature of an increasingly refinery-driven market, and export-driven to a lesser extent.
]]> Los Angeles CARBOB, the main California-specific gasoline grade, entered May at June NYMEX RBOB futures plus 20 cts/gal, moved to plus 55 cts on May 11 and fell to flat by Tuesday of this week, as assessed by Platts. On Wednesday it jumped 13.5 cts/gal on the cash differential against a new trading month. (Obviously, the end price also is affected by swings in the outright NYMEX price.)Eleven of those 17 trading days saw differential swings of 5 or more cents, or roughly $2/b, a fairly large shift in the cash market. But it's not unheard-of out West. August, September, October, November, February, March and April each had at least 5 days of such daily swings.
Differentials gained 43.75 cts/gal in little more than a month late last summer, dropped 40 cts/gal in a similar span in the fall, and gained almost 30 cts/gal in just one day in February before dropping 56 cents/gal over the next month. Those are swings of up to $12 to $24/bbl even before accounting for the underlying NYMEX contract.
It's not just Los Angeles. Portland unleaded nearly doubled its differential Wednesday as it traded at $1.10/gal over the NYMEX. That's $46/bbl over the June NYMEX, which itself was at $2.82/gal, or $118.50/bbl.
The common refrain among traders: "The West Coast is an island." Just like US weather patterns, the region is rarely linked to what happens elsewhere in the nation.
The other common refrain: "It's a refiner's market."
The West Coast is now nearing an end to an extended spring maintenance season coupled with outages at key refineries. Refiners used only 70.5% of their capacity in early April, the second-lowest weekly run rate since the US Energy Information Administration started keeping specific PADD records in June 2010. The government data also showed stocks last week hit a 13-year low as the summer driving season approaches. The fall season saw similar, though slightly less stark, stock and run rate trends on weak gasoline margins.
Still, West Coast distillates experienced similar data decay with little market volatility. Why the divergence? Several refiner-related reasons there, too. Start with a switch from summer-grade to winter-grade specifications and then back again in a time of high crude oil prices and extremely weak demand. CARBOB especially is a more liquid market, but it's also a tough California-specific gasoline grade. It doesn't travel well outside of California, unlike the more global diesel and jet fuel markets.
That's not to say exports and imports didn't play a strong role for CARBOB, which was introduced in 2004. A record low differential in late July attracted South American demand for California-grade gasoline and popped the spot market higher. The large February spike deflated partly due to Asian gasoline cargoes. And problems at Mexico's sole Pacific refinery created a need for quick cargoes in early May just as three San Francisco Bay Area refineries entered maintenance. Los Angeles spot CARBOB hit a three-year high at the time, and its San Francisco counterpart moved to a rare sharp premium over Los Angeles.
Players will cite many other factors for the bouncy gasoline market, from illiquid future markets to several active traders leaving the market. They may also shrug and say West Coast gasoline has always seen sharp trading waves. But it's unlikely they've seen the crests and troughs quite like the recent waves reaching the island known as the West Coast.
]]>In a webinar held Tuesday morning, Genscape's Abudi Zein (full disclosure: a former Platts colleague) reviewed some of the many pictures his company has taken from the air or from satellite imagery over the 800 kilometers of the just-reversed Seaway Pipeline between Cushing and Freeport, Texas.
]]> One of the things that Genscape has spent a lot of time looking at are the pumping stations being worked on down the line. Zein pointed out that the line flows from as much as 300 meters above sea level down to zero elevation at Freeport, so gravity is a contributing factor in pushing oil through the line.But it's not all gravity; the pumps do matter. And furthermore, Zein said the combination of how many are in use and what type of crude is flowing down the line will impact Seaway's capacity.
Genscape as of yet does not have any indication that Seaway has started to utilize the first major pumping station, at Colbert, Oklahoma. It is able to monitor the power flow into a pumping station, and that is a sign whether it's operating. But still, "as we turn the pumps on, we can see through the model what the total flow is going to be," Zein said.
The number of pumps in use is significant when combined with the type of oil going through the line, because the line will be able to carry a greater quantity of lighter crudes such as WTI or a WTI look-alike than it can carry of heavier Western Canadian Select (WCS). So according to Genscape calculations, if Seaway is using one pump at Cushing, it can move 150,000 b/d of WTI. That figure was cited by the Seaway operators -- Enbridge and Enterprise Partners -- as the initial flow. A second pump brings capacity up to 200,000 b/d, 220,000 b/d for three pumps, and 250,000 b/d for four pumps.
Meanwhile, one pump at Cushing gets just 130,000 b/d of WCS down the line. If you get up to four pumps, the capacity rises only to 175,000 b/d.
So if it's WCS going in the line to fill it, Zein said, "you'll probably need Colbert (a pumping station in Oklahoma) and (the pump at) Cushing to get that 150,000 b/d. So that's why we believe it is much more likely that what we will have in the beginning is a line fill with light crude rather than with heavy crude. So we think what it being pumped into the line now is WTI or a WTI lookalike that is not heavy crude."
Movement on the pipeline began last Saturday. Zein said it would take 15.2 days for the line to fill, and when it does, it will have 2.3 million barrels.
Although Zein said Genscape believes it's mostly WTI or WTI look-alike now in the line, he said that given the disparity between amount of coking capacity in the US Midcontinent and the capacity in the Gulf Coast region, he expects a great deal of the flow on Seaway will be heavier crudes that can take advantage of that capacity. (Though he didn't mention them, there are several large refining projects in the Midcontinent underway to increase that region's capability to process heavier Canadian crudes.)
The planned ECHO storage terminal being developed by Enterprise near Freeport, which will take in crude from both Seaway and the Eagle Ford development in South Texas, has direct connections to roughly 430,000 b/d of coking capacity, Zein said. That's about double the Midcontinent, so the appeal of getting heavy crude down to ECHO via Seaway is obvious. But that impacts the total flow.
"If the appetite for heavy sour asserts itself, as we think it will, the rate of that flow will decrease," Zein said, as the lighter crudes presumed to be in the line now are displaced by heavier crudes and their slower rate of delivery.
]]>The company that owned it, E.ON Ruhrgas, was one of the giants of the gas establishment, starting off in the middle of the last century to develop a formidable battery of pipelines, production assets and natural gas purchase and supply contracts.
How the 12,000 kilometer network develops in the future -- dislocated from the former parent company's gas procurement and supply business -- will be watched with close interest by those involved with Europe's energy markets.
]]> Ruhrgas was a very successful operator. Its contracts with Norwegian, Russian and Dutch gas producers were the source of much of its wealth, as the import price sharply increased as the gas went through its pipelines to its customers. Most of its shareholders -- before they sold at a large profit to E.ON -- were also some of the biggest gas producers in Europe: ExxonMobil, BP, Shell, and others. As its suppliers, they also had an interest in its profitability. Its business model was robust.From its inception, there was never any competition, as other gas suppliers in Germany did not move beyond their own regions by mutual agreement, and Ruhrgas' footprint was the largest. And nobody else could use its pipelines as they could not prove that Ruhrgas had spare capacity.
And as pipeline capacity requests from new entrants had to stipulate entry and exit points, a major customer supplied off the Ruhrgas network who might be in talks with a would-be competitor could expect to have a visit from a salesman from Ruhrgas offering an even better price. Ruhrgas could afford to discount to retain customers.
Not that the company was content merely to lie back and enjoy the benefits of its impregnable position. It invested in the UK-Belgium Interconnector, giving it access to what then was a source of relatively cheap gas--even as its own oil-indexed import contracts were rising--and the means to bring it home. That stake now also has been sold: the $160 million stake in the Interconnector now is part of a new pipeline partnership that belongs equally to a pairing of transmission system operators, Italy's Snam and Belgium's Fluxys.
And until quite recently the German giant was coming up with new ideas for projects to invest in. For example, E.ON Ruhrgas still has a stake in the TransAdriatic Pipeline project, to bring Caspian gas into Italy (15%); and there is the Tauern pipeline project, to bring gas into Austria from Italy (45%).
E.ON Ruhrgas also has a stake in the first, operational line of what will be the 55 Bcm/year Nord Stream line, bringing Russian gas to Germany under the Baltic Sea, for the first time avoiding Ukraine and Belarus; and in the Nel and Opal lines, which will bring that gas onshore westward and southward.
Although for how much longer it will have these stakes for is anyone's guess. However, fatally, it refused to read the writing on the wall. With liberalization, the advantage in owning pipelines is less important. No longer can a company cross-subsidize its customers by charging other companies high transport fees. And with competition comes market risk.
Ruhrgas had been buying up as much term gas as it could, even until quite recently, with the contracts with Russian Gazprom to underpin Nord Stream all sold on traditional oil-indexed terms, seemingly unable to contemplate a future without these contracts.
This upstream length coincided with a surge in shale gas production in the US. A wall of LNG from Qatar turned a potential asset into a massive liability. E.ON is still negotiating with Gazprom to reduce these terms, having already reached agreements with Norway's Statoil and Dutch GasTerra. These money-losing contracts will be part of the E.ON Energy and Trading business by the end of this year.
The key point of market liberalization in Europe was unbundling the ownership of gas supply from the means of gas transportation and storage. In fact, the failure of the European Union to have its way on legal separation, ever since the first of the successive gas directives was issued in the late 1990s, was always held as a fatal flaw. But some companies carried on regardless.
Ruhrgas, Italy's Eni, and French GDF Suez were often to be found in actual or suspected breach of competition law. It was the competition department, rather than the energy and transport department, that proved to have the teeth, enforcing the sale of pipeline capacity and greater transparency on the transmission system operators.
Forced to divest pipeline capacity and to market it at arms' length to all comers on a non-discriminatory basis, the owners derive far less value from their investments than previously. The question is whether the new owners will invest in them as needed, or whether they will prefer to sweat them hard, to the detriment of supply security. Firm and intelligent regulation will be needed to oversee this work.
]]>China has had to cut domestic gas production to make space for imports amid a seasonal dip in demand over the second and third quarters of the year.
The country produced 8.5 billion cu m (10 Bcf/d) of gas in April, up 8.6% year on year but down 25% from March, official government data showed. Production last year similarly tapered off after a strong first quarter -- output in April 2011 fell 25% from March to 7.8 Bcm.
This seasonal drop in production began only after piped gas imports from Turkmenistan ramped up in the second half of 2010, according to analysts. The decline in 2010 was narrower with April output down just 4% from March at 8 Bcm.
"As the weather warms up, less gas is needed for heating...so domestic production has fallen. There are no gas storage facilities and we cannot stop importing gas because of already agreed offtake volumes in contracts," said Xu Bo, senior analyst at state company China National Petroleum Corporation's Research Institute of Economics and Technology.
Tony Regan, gas consultant at Tri-Zen International in Singapore, echoed a similar view.
"At the same time [as demand declines] imports of LNG and piped gas from Turkmenistan are increasing. They can't turn these off, as apart from spot LNG deals, there are take or pay clauses," he said. "So they seem to be balancing on domestic production."
In China, gas demand primarily comes from residential and industrial users in cities, with a small volume going to the transport sector as compressed natural gas, where it displaces relatively more expensive oil.
CNPC started receiving gas from Turkmenistan in late 2009. Under its contract, China is to lift 30 Bcm/year and volumes will go up to 40 Bcm/year from 2015. Meanwhile, contracted LNG to China for existing and future projects expected to start within the current decade is close to 35 million mt/year.
Xu said state-owned companies including PetroChina, Sinopec and CNOOC likely reduced output from China's largest gas producing areas to bring down overall production. These include Changqing in the Ordos Basin, which produced an average 2.5 bcf/d last year; the Tarim Basin in western Xinjiang province, which produced an average 1.6 Bcf/d; and Qinghai in the Qaidam Basin in northwestern China, which produced an average 628,600 Mcf/d.
"Demand should ramp up again in the fourth quarter towards winter," Xu said. Last year domestic production in the second and third quarters averaged 9.4 Bcf/d, while fourth quarter output was 10.5 Bcf/d.
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Pricing is also a sticky issue with domestic gas producers. China's gas pricing regime gives domestic operators few additional incentives to produce more gas than is needed, Regan said.
China's natural gas prices are fixed at levels way below cost and as with other fuels, Beijing has been reluctant to push through reforms because of its potential inflationary impact on the economy.
The last gas price increase was in June 2010, when the government hiked wellhead gas prices by 25% to an average of Yuan 1.155/cu m ($4.69/MMBtu).
But as China's gas demand and import dependence grows, state companies are clamoring for pricing reforms.
CNPC's listed subsidiary PetroChina said it lost Yuan 21 billion ($3.3 billion) in 2011 on LNG imports and pipeline imports from Turkmenistan.
CNPC's contracted price for Turkmen gas delivered to the Chinese border is understood to be well above $5/MMBtu. The value of the LNG imports in the first quarter this year averaged $547.71/mt or $10.53/MMBtu, versus $375.93/mt or $7.23/MMBtu during the same period in 2011.
The government in December last year introduced a new pricing mechanism on a trial basis in the provinces of Guangdong and Gaungxi. The mechanism uses a basket of high sulfur fuel oil and LPG prices traded in Shanghai in a 60:40 ratio, calculating natural gas prices in both provinces based on 90% of the market price of the basket. In the past, the price was set using a cost-plus method taking into account pipeline and other tariffs.
PetroChina along with rivals Sinopec and China National Offshore Oil Corporation are now hoping for this new pricing mechanism to be extended to more regions.
China's total gas imports in the first quarter of this year stood at 9.7 Bcm, up 65.5% year on year, according to the National Development and Reform Commission.
Customs data show LNG imports were up 41% year on year to 3.26 million mt (1.74 Bcf/d) and pipeline imports from Turkmenistan nearly doubled to 5.2 Bcm during the period.
Apparent demand for gas grew 19.7% year on year in the first quarter to 39 Bcm, the NDRC said last month.
Imports will likely grow further this year which could mean a further tapering off of domestic production.
CNPC's General Manager Zhou Jiping said in March the company would import 4.2 Bcm or around 3.05 million mt of LNG in 2012, more than double the 1.83 Bcm it imported last year.
--Yen Ling Song in Singapore
]]>But despite prophecies of doom and gloom on both sides of the case leading up to that decision, the ultimate outcome of the ruling may have a smaller impact on the
And US solar developers said tariffs would make it more expensive to build new solar power projects here, potentially smothering US PV development.
But after the DOC decision, of the largest Chinese PV manufacturers--Suntech and Yingli Green Energy -- said they are already prepared to shift their production and use their global supply chains to sell the
"We're fully prepared to handle this situation and we believe that we can continue to supply the
Andrew Beebe, Suntech's Chief Commercial Officer said Suntech has similar plans.
"As a global company with global supply chains and manufacturing facilities in three countries, including the
Commerce proposed levying 31.14% tariffs on Trina Solar, 31.22% on Suntech and 31.18% on all other Chinese solar companies that participated in the government's investigation. Commerce recommended a 250% tariff be imposed on the mostly smaller solar firms that did not participate in the case, according to a Commerce Department fact sheet.
GTM Research Solar Analyst Shyam Mehta said Chinese companies will likely use one of two strategies to avoid US tariffs: either shift production outside of China, as Suntech's Beebe described, or use Taiwanese suppliers to make cells, which would be assembled into modules in China through a process called "tolling."
"We estimate that tolling cells to Taiwanese firms would increase Chinese costs by 6-12%, which is meaningful but manageable," Mehta said.
Shifting production to other sites to avoid tariffs is well within the bounds of US and international trade laws, according to White & Case international trade attorney Scott Lincicome.
"That's certainly not illegal," Lincicome said. "What's illegal is when you make it in
To prevent companies from illegally labeling Chinese-made panels as coming from another country, Commerce and the US Customs and Border Control will require solar panel imports to include documentation about where solar cells and modules were produced, said SolarWorld attorney Tim Brightbill.
"Commerce has clearly coordinated with Customs in advance on this, so importers will have to be able to certify where these cells and modules are coming from," Brightbill said.
Some Chinese suppliers will likely shift a portion of their operations to the US as a result of the tariff decision, Mehta said, but in the long term, other countries with lower production costs will likely benefit.
"We see the impact of this decision on US manufacturing as positive, but spurring limited investment in the future and likely only temporary relief for existing U.S.-based suppliers," Mehta said.
SolarWorld and six other companies alleged in their complaint that China's national and local governments have illegally provided more than $40 billion in annual subsidies to solar cell and panel manufacturers, including cash grants, loan guarantees, lower-cost inputs, discounted export insurance and other aid. That aid has allowed Chinese companies to dominate the
The trade rulings apply only to certain Chinese-made polysilicon solar cells and panels, not thin-film PV panels or other types of solar equipment.
Despite warnings that new tariffs could lead to retaliation by
"There's going to be a lot of bluster, but at the end of the day this is not going to be something that's going to ratchet up the tensions in reality," he said.
]]>I haven't provided this brief resume in an attempt to find new employment. Acceptance of another full-time job does not fit in my definition of retirement. Some retire to write a book, but I'll be leaving to read one. Since my editors at Platts requested a swan-song blog on my thoughts about the industry, however, I felt I should preface my remarks to you, the titans of energy commerce, with a brief roundup of my qualifications as an independent observer.
My experience with the oil and gas industry actually dates back to 1980, when, as a Houston-based freelancer, I became the first contract correspondent for the AAPG's monthly Explorer publication, juggling coverage on the science of things like the Austin Chalk, the Gulf of Mexico's subsalt breakthrough and enhanced oil recovery in the Permian Basin with assignments on immigration reform for Time and colorful Texas court cases for The National Law Journal.
You won't remember this now, but, when I joined Oilgram News in 2004, the industry was in shock because the price of oil had jumped all the way to $30/barrel. Imagine this: Back then, independents were still drilling primarily for natural gas instead of oil and wondering if they should rename the Gulf of Mexico after the Dead Sea. I expected my final career phase with the trade press to be some kind of quiet period where I could downshift into cruise control for one last lap around the journalism track. So, what did you do to me?
Sometimes it seems like I've spent more quality time in courtrooms the last eight years than I did covering courts for The Houston Post in the 1970s. A Russian oil company wanted US bankruptcy protection. A CFO for a drilling company embezzled $70 million. Rogue oil traders defrauded a corporation. A Mexican drug cartel hijacked oil shipments. The late Ken Lay sought mercy for his "aggressive" investment practices. And, beyond the show in the courtrooms, the 2010 Macondo crisis wins my top award for best performance by a news event in the sector-turmoil category, providing an assignment reminiscent of a prison riot I covered in 1974. Instead of monitoring a warden's 13-day negotiation for a hostage release, I spent three months in 2010 watching BP's daily efforts to cap a runaway well.
When I wasn't busy explaining turmoil in the industry, however, you were busy reinventing yourself with operational and business breakthroughs that demanded more thoughtful analysis. With the Jack appraisal well in 2006, you proved the commerciality of the Gulf's Lower Tertiary. With horizontal drilling, you have given new life through shale exploration to what had been a dwindling US hydrocarbon base. You have sown the seeds for a real rennaissance in oil production certain to blossom in the next decade. In the process you also likely have paved the way for a manufacturing renaissance as well, based on the availability of low-priced power generation from cheaper natural gas. Of course, most of you also have gotten filthy rich along the way, but isn't that how motivation works to the public's advantage in our system?
So, as I close the cover on my Platts laptop for the last time, I realize that not only have I had an exciting time with a front-row seat for this great show, but I also have been a witness to a significant turning point in American industrial history. Thanks for the opportunity to write all these stories.
I've left you in pretty good shape at this point. No, I can't accept all the credit for what you have accomplished in the last eight years. But I do feel like my part of the work here is done. You should know, however, that old journalists never really go away. This byline may not be my last. I'll still be watching you.
]]>Or as ecologist Garrett Hardin succinctly put it: "You can never do just one thing."
]]> That's what the imminent startup of the reversed Seaway oil pipeline brings to mind. Its slated in-service date this week should alleviate backed-up crude volumes at Cushing, Oklahoma, and bring prices there more into line with those on the Gulf Coast. But it also leaves a new area of oversupplied, relatively lower priced crudes that bears watching: Midland, Texas.Oil produced from the Permian Basin in West Texas and southeast New Mexico, which is priced at Midland, is already valued below Cushing-priced crudes due to a tsunami of Permian output, observers say.
A wealth of geologic horizons to exploit and technologies that yield production efficiencies have turned the Permian into a horn of plenty oil-wise. But not enough infrastructure exists to take away all of the output galloping toward Midland. The result has been lower prices for those crudes.
"With pipeline capacity constraining booming Permian oil supply growth, Midland crude prices have blown out relative to WTI [West Texas Intermediate at Cushing], which itself is already heavily discounted" to Brent-priced crudes on the Gulf Coast, Deutsche Bank analyst Paul Sankey wrote in a May 14 report.
Seaway, with an initial 150,000 b/d capacity--rising to 400,000 b/d by early 2013 and 850,000 b/d by mid-2014--"may well exacerbate this discount, as it will alleviate oversupply at Cushing, but do nothing for the Midland bottleneck," Sankey said.
The WTI Midland-WTI Cushing crude differential reached just under minus $9/b on April 5, the widest since at least July 2001, according to Platts data. On May 14, it was minus $5.50/b.
Midland volume growth is "through the roof right now," Macquarie Securities analyst Chi Chow said. "There's limited capacity to move that crude to different markets."
Chow, citing Energy Information Administration data, noted that between January 2011 and February 2012, Permian production increased by nearly 350,000 b/d to 1.6 million b/d. EIA is the statistical arm of the US Department of Energy.
Market sources also expect Midland crudes to remain discounted to Cushing as Permian output continues to outpace takeaway capacity. "Even with Seaway coming online, you are still constrained coming out of the Permian into Oklahoma," one source said. "Rail [is] helping some, but not enough yet."
Seaway, which is expected to begin deliveries May 17, is a 50:50 joint venture between Enterprise Products Partners and Enbridge. The 500-mile pipeline runs from Freeport, Texas, to Cushing. The partners reversed the line so it can bring more oil to Gulf Coast refineries and alleviate what a few years ago became a bottleneck at Cushing caused by swarming crude volumes out of the North Dakota Bakken Shale and Canada.
In the end, the solution for Midland is more takeaway capacity, analysts said. Just as Seaway should relax price spreads between Cushing and pricier Gulf Coast crudes, so should planned pipeline expansions aimed at finding new homes for Midland-area crudes ease price imbalances there. Transportation plans include Magellan Midstream's reversal of the former Longhorn Pipeline that had run from Houston to Crane, Texas, and an expansion of Sunoco Logistics' West Texas Gulf line from the Permian to Longview, Texas.
That will bring Midland crude prices into better equilibrium with the Gulf Coast, although Permian producing keeps rising fast. In fact, given the dizzying pace that industry is finding new geologic plays in the US midsection, it may not be long before another price imbalance rears up -- somewhere.
By the way, Garrett Hardin also coined the phrase "Nice guys finish last," and wrote an important early paper in the field of environmental geology called Tragedy of the Commons,. detailing the perils of self-interest even when innocent.
]]>The development of unconventional resources is the "biggest thing" BHP Billiton Petroleum Chief Executive Mike Yeager has seen in 33 years in the industry. "It's bigger than 2D to 3D seismic, it's bigger than shallow water to deep water, because it's going to double the hydrocarbons available to the world," Yeager told journalists on the sidelines of the southern hemisphere's largest gathering of oil industry executives.
]]> Total Chairman and CEO Christophe de Margerie flagged growing production of crude oil and a "golden age of gas." He cited International Energy Agency estimates of 1 trillion barrels of technically recoverable oil shale resources, a significant portion of which is in the US, and the various forms of tight gas, shale gas and coalbed methane. These, he said, would extend the time horizon to 100 years for oil and 130 years for gas.ExxonMobil gas and power marketing vice president Emma Cochrane described "transformational change in energy and how it is delivered."
Cochrane reminded delegates of recent comments by the US oil and gas giant's chairman Rex Tillerson, who said the transformation unfolding in North America represented a "potentially decisive shift" in the history of energy.
"We may well be on the cusp of an epic rejuvenation of the energy industry not only in the United States and here in Australia, but around the globe," she said.
Saudi Arabian oil minister Ali Naimi was only slightly less upbeat. He told the conference that he saw the future of oil and gas as "less revolution, more evolution," but added that the industry was enjoying a period which offered "once-in-a-generation opportunities to both Australia and Saudi Arabia."
APPEA Chairman and Santos CEO David Knox extolled that it was "an exceptionally exciting time to be a part of the Australian oil and gas industry," which is in an "unprecedented phase of growth and expansion" with $170 billion worth of new LNG projects currently underway. On the east coast alone, the development of coalseam gas reserves for both the domestic market and for three sanctioned LNG export projects was "ultimately amazing wealth creation" for Australia, he told journalists.
According to Knox, just the speaker list at this year's conference was indicative of the buzz surrounding the industry.
"You've got Exxon speaking at this conference, you've got Chevron who are a massive investor in Australia, you've now got Christophe de Margerie who is one of the leading CEOs in the oil and gas industry. We've even had the Saudi oil minister!" Knox said. "There's a lot of interest in this country...the only questionmark is will we make sure that we create a stable investment climate."
]]>The South Korean government can't be accused of not trying. The administration of President Lee Myung-Bak has been working very hard over the past year to lower gasoline and diesel pump prices and has come up with some creative solutions.
The fact that retail oil prices have continued to rise can only be attributed to the country's absolute dependency on imported oil, which makes it vulnerable to volatility in international markets. South Korea imports around 2.5 million b/d of crude, with more than 80% of that coming from the Middle East.
The four local refiners have been at the receiving end of most of the government's measures to cut prices. SK Innovation, GS Caltex, S-Oil and Hyundai Oilbank almost fully control the supply chain from production to retail through exclusive contracts with the country's 13,000 retail outlets, around 25% of which are directly operated by them.
The government has held refiners responsible for high pump prices and has accused them of acting as an oligopoly, even fining them for price collusion.
For their part, the refiners say pump prices are linked to international markets and follow global trends, a position that is supported by a closer look at the numbers. Retail gasoline prices in South Korea had increased by 4.7% year on year to Won 2,030 ($1.79)/liter at the end of March, according to data from state-run Korea National Oil Corporation. Over the same period, benchmark Mean of Platts Singapore 95 RON gasoline gained 11.76% to $136.46/b, or 86 cents/l.
In an effort to boost transparency and competition, Seoul earlier this year set up "discount" gasoline pumps and launched an online spot trading platform for oil products. There are currently 450 discount outlets in the country and the target is 1,000 before the end of the year.
These outlets are supplied by KNOC, which in turn buys fuel via tender from refiners and importers. More recently, the government signed an agreement with Samsung Total Petrochemicals to supply gasoline produced at its petrochemical facilities to the discount pumps. Samsung Total has until now been exporting all the gasoline it produces.
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Average gasoline and gasoil prices at the discount stations are around Won 35-40/l or 1%-2% cheaper than regular outlets, one energy ministry official said. But prices are expected to drop further once new fiscal incentives--mainly tax breaks for the discount outlets--kick in and Samsung Total starts supplies, he said.
The new online oil products spot market was launched on March 30, in theory providing a trading platform for the retail station owners as buyers and the refiners and importers as sellers. But daily trade has so far just been 81,000 liters of gasoline and gasoil, a tiny fraction of national demand of around 90 million liters.
The online market's poor performance has prompted the government to offer a tariff exemption on any imported products traded, compared with the 3% levy imposed on products sold in the regular market. Seoul also offered to refund Won 16/l of tax on imported products traded online and has eased regulations to boost imports.
Starting this month, oil importers are not required to maintain stocks equivalent to 30 days of imports and can qualify to import refined products as long as they have minimum storage capacity of 5,000 kiloliters (31,500 barrels), down from 7,500 kl earlier.
Prices on the online market have been Won 10-50/l lower than supply prices by oil refiners at regular outlets. "Online prices would be [further] lowered when more oil importers and refiners join the market," the ministry official said.
The government has also turned its focus on consumers and is planning measures to curtail rising demand. South Korea's products use in the first quarter of 2012 rose 1.2% year on year to 209.11 million barrels, according to KNOC, with gasoline use up 5.3% at 17.18 million barrels and diesel up 1.9% at 32.71 million barrels.
"The government has taken various steps to bring down retail oil prices, which have focused on suppliers, but the demand side should be addressed as well," one energy ministry official said. The measures, expected to be announced in coming weeks, might include regulations to lower oil demand for power generation and automobiles.
Critics meanwhile have blamed high taxes, which account for 45% of pump prices, and an export-oriented foreign exchange policy for the high domestic oil prices. Given any appreciation of the local currency, the won, would damage exports--which account for 53% of South Korea's GDP--the only viable choice appears to be a tax cut.
Oil taxes accounted for 14% of the government's revenue in 2010, however, and Seoul has ruled that option out.
"The government will consider lowering taxes on oil prices [only] if the price of Dubai crude stays above $130/b," a senior finance ministry official said recently. With Dubai now at $116/b, South Koreans might just need a higher oil price in order to pay less to fill their cars.
--Mriganka Jaipuriyar in Singapore
]]>Under an order CFTC commissioners signed off on before a meeting Thursday, the effective date of many new derivatives regulations that Congress had ordered to be in effect by July 2011 will be pushed until the end of 2012. All the light that the clearing, reporting and position limits rules were expected to bring into the long, dark over-the-counter derivatives markets by now will remain off until probably next year.
But even early 2013 might be a stretch, according to Commissioner Scott O'Malia, who said Thursday that "unless the Commission focuses on its priorities, it seems unlikely we can meet this schedule."
The order, approved Thursday, is the third such order the agency has approved since it began its marathon rulemaking process just days after President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act into law in July 2010.
"I don't know of another agency that has worked so hard and accomplished so much," CFTC Commissioner Bart Chilton said this week.
But it's fair to say that commissioners had no idea when the process began how little would actually be accomplished by now.
Despite a frenetic work pace and, by all accounts, grueling schedule for CFTC staff, the agency is still less than two-thirds of the way through finalizing the more than 50 new rules mandated by Dodd-Frank. It's still unclear when final rules on margin, capital and swap execution facilities, among others, will be voted on and some key reforms, like the commodity position limits regime the agency finalized in October, have yet to be imposed.
Those limits are also being challenged in court by two major Wall Street lobbying groups.
In addition, some rules, particularly registration requirement for market players, may go into effect before margin and capital rules are finalized and the CFTC decides how the new rules will apply extraterritorially, or outside US borders, according to Commissioner Jill Sommers.
The CFTC seems to "have a penchant for putting the cart before the horse," Sommers said. "I am concerned that as we get closer to the finish line we may look back only to realize that no one is capable of crossing it."
On Thursday, O'Malia released a proposed schedule for finalizing rules through the fall. This includes, for example, finalizing core principles for swap execution facilities in July and finalizing the Volcker rule in the fall.
"I frequently hear from industry that the Commission's rules are not sequenced in a manner that provides them with the certainty they need to make budgeting, investment and hiring decisions," O'Malia said.
After Thursday's meeting, CFTC Chairman Gary Gensler told reporters, as he has done in the past, that the agency was not going to rush to get the rules done. The CFTC rules would be done right, in a balanced way and "not against a clock," he said.
Wrapping up day 1 of the Platts European Oil Storage Conference in Amsterdam was a panel of several of that day's speakers. Two subjects stood out in the discussion: the sad situation of European refineries, beset by closures and poor margins, and the opportunities to build storage in the Mediterranean. Here are a few of the key points made by some of the panelists, mostly paraphrased, but with some direct quotes.
]]> The MedMark Lewis, managing director for Europe at Facts Global Energy: If you look at the future of the Med, you can see increased crude supplies coming from the Caspian, and you have the potential at least for increased supplies from Iraq, which will use the northern pipelines from Ceyhan. Meanwhile, you have a vibrant, growing market in Turkey. As there is inevitability of growing products trade coming through the Suez Canal, when you go longer distances, you will tend to use larger tankers, because that will help carry a broader mix of products. Suezmax tankers increasingly will be used, so there are identifiable, significant changes, which will all tend to indicate the need for more storage facilities in the Med.
The Middle East will build more refineries. The products from them won't be going East, because Asia has enough refining capacity. So they therefore will send that product to the West. It's a long-term trend. It's not going to end next year or the year after. It's going to happen over the next 10 years, and that's the furthest any of us can look ahead.
(Responding to a question from the audience): It's not likely that we're going to see products put on ships from the Middle East and sailed around the Cape of Good Hope. Product tankers that are too big run into problems offloading at smaller ports that can't handle ships that big.
Rob Luijendik, managing director, TankTerminals.com: We do not see the Med as a coherent market. There is a European side, and there is an African coast, and there are large differences. There are a great number of countries on the northern border of Africa with their own mentalities and opinions. It is one of the most highly fragmented markets. There are also differences between the eastern and western Med countries.
You see some signs that international companies are showing interest in operating tanks and building up to get their foot in the door.
Given the enormous amount of world oil flows that go through the Black Sea and/or the Med, the amount of storage capacity in the Med market is out of relation to those flows. It is justified that more attention will be paid and that this market will be rectified. Things will change.
Europe's refining crisis
Chris Hunt, director general of the UK Petroleum Industry Association: There's a meeting on May 15 of key European energy ministers and other officials to discuss the status of Europe's refining sector. They need to start making some very swift decisions.
Even with all the focus on alternate fuels, by 2030, 80% of all transport fuels will still come from oil. The decision is where we want this oil to come from. Is it from an indigenous marketing base or imports? The latter would be great news for tank storage companies, but in terms of energy security, is this where you want to be?
More Lewis: The implication of closing these refineries is a question of whether we in Europe feel more secure importing crude or products. Generally around the world, countries have been more comfortable importing crude. China has made a strong decision that they will not be dependent upon product imports, and they are building refineries to ensure that doesn't happen.
We see the issue of dieselization as one of the major issues which is really undermining profitability in Europe. It was created artificially by governments, and for whatever reason, they encouraged diesel.
The EU has had chances to narrow the tax gap between diesel and the higher levies on gasoline, but have failed to do so. This has not been discussed at the EU level in any proper forum, and it's about time they did.
Addendum: In an email exchange with Mark a few days later, he expanded on his views that dieselization had hurt the European refining industry. Our view was that since diesel is the most profitable part of the barrel, why would a program that (we believed, incorrectly, according to Mark) ultimately encouraged the construction of more diesel capacity been damaging? Here's his response.
]]>The problem with dieselisation is not a current issue but one that has been building up for 20 years or so. Essentially, the EU encouraged more diesel/less gasoline by tweaking the tax but the European refineries generally did not invest to match this change, relying instead on the convenience of exporting surplus gasoline to the USA and importing deficit diesel from Russia. The European refinery configuration has therefore been progressively getting further away from European demand pattern. It all worked fine until the US gasoline demand/imports fell and the European refiner couldn't dispose of its excess gasoline, which constrained runs, worsened the economics and still meant a shortfall of diesel. You can't put all the blame on the governments, the industry did not adjust to the changing local market but this would have required substantial investments in a sector which was already having to be invested in because of quality spec tightening (sulphur removal) and which was never making much money.